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OTC 22714

Tools and Techniques for the Selection and Design of Safe Deepwater Riser Systems for Mobile Offshore Drilling Units Alan Whooley, MCSKenny Jonathan Deegan, Riskbytes Riley Goldsmith P. E., Goldsmith Engineering Adriana Botto, WGIM

Copyright 2011, Offshore Technology Conference

This paper was prepared for presentation at the Offshore Technology Conference Brasil held in Rio de Janeiro, Brazil, 4–6 October 2011. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessar ily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.

Abstract The deepwater drilling industry has been rocked by the tragic Deepwater Horizon event in the Gulf of Mexico. The incident

identified a number of possible failings by operator, service contractors and the regulator which combined to lead to the

ultimate results which were evident in mid 2010. This paper will assess the options available to the deepwater drilling

industry in assessing the risk of various riser and BOP configurations for drilling and completing deepwater wells in

moderate metocean environments. The paper will address two different systems (as presented in Figure 1):

1. A classic subsea BOP stack configuration,

2. A surface BOP stack with a subsea isolation device (SID).

Both of these configurations have merits depending upon a number of factors which include rig availability and schedule,

project economics, riser integrity, BOP configuration, geological issues and, most importantly, the hazard and risks

associated with each concept.

This paper will identify the various technical analyses and risk analysis techniques that must be undertaken to assure the

operator of the system is comfortable with each system. These include riser analysis, rig mooring and station keeping

analyses, system HAZIDs and HAZOPs, and more.

The idea of the paper is to provide the operator and drilling contractor with a ‘road map’ which will allow them to navigate

their way through the various issues to be addressed. This road map will start with the concept stage (rig contracting and

early well planning) where issues such as project economics, rig availability and risk tolerance will provide input into the

overall decision making process. The paper will next address the preliminary and detailed design stages where issues

surrounding metocean criteria, rig characteristics and rig configuration and geological conditions will play a part in the

overall input. The paper will describe how a project team would approach the issues. Finally as the project moves to the

implementation stage the paper will describe the techniques for final assurance that the concept can be managed in the

implementation stage.

Acronyms ALARP As Low As Reasonably Practical

AAR After Action Review

BHA Bottom Hole Assembly

BOP Blow Out Preventer

DP Dynamically Positioned

DTL Dynamic Tension Limit

EAC Environmentally Assisted Cracking

ECA Engineering Criticality Assessment

EDS Emergency Disconnect Sequence

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FAT Factory Acceptance Testing

FEED Front End Engineering Design

FDPSO Floating Drilling Production Storage and Offloading

FMECA Failure Modes Effects and Criticality Analysis

HAZID Hazard Identification

HAZOP Hazard Operability

HSE Health Safety and Environment

JSA Job Safety Analysis

LMRP Lower Marine Riser Package

LFJ Lower Flex Joint

LSJ Lower Stress Joint

LWD Logging While Drilling

MODU Mobile Offshore Drilling Unit

MWD Measurement While Drilling

MUX Multiplex

QA Quality Assurance

QC Quality Check

QRA Quantitative risk assessment

RAM Reliability, Availability, and Maintainability

ROV Remote Operated Vehicle

RCM Reliability Centered Maintenance

SBOP Surface Blow Out Preventer

SSBOP Subsea Blow Out Preventer

SID Subsea Isolation Device

SIT System Integration Test

TJ Telescopic Joint

TLP Tension Leg Platform

UFJ Upper Flex Joint

VIV Vortex Induced Vibration

1 Introduction

The offshore industry has used Surface BOP (SBOP) stacks and casing riser systems to drill a relatively large number of

wells over the past 15 years, especially in the Far East. One or two major operators have expanded the concept to other

geographical locations which have more moderate environmental conditions. This move has been relatively slow and has not

been adopted as yet in some locations where the surface stack system could offer both financial and risk benefits.

This paper describes a methodology for undertaking an assessment of the risks and practicalities of using a Surface BOP

stack against the conventional approach of using a Subsea BOP (SSBOP) stack for deepwater operations. The paper

describes the history of SBOPs, gives an overview of the system components, the pros and cons of the two systems, the

engineering analysis required to justify a SBOP system and finally the risk assessments that are recommended to be

conducted to undertake an SBOP operation in deepwater.

The methodology presented in this paper is intended to facilitate a side by side evaluation of the different configurations. A

transparent and tractable methodology also ensures consistency across all facilities, allowing for better transfer of knowledge

and application of lessons learned between projects.

2 Historical Review

History of Surface BOP Stacks

SBOP drilling operations from moored MODUs have progressively developed since 1996. The SBOP technique has been

extensively used in the benign metocean conditions as experienced in South East Asia. The first recorded instance of the use

of a SBOP stack was in Nigeria on the Sedco 135 in 1967 (Ref 1).

Since that date back in 1967 and up to 2005 over 150 subsea wells have been drilled in varying water depths with Surface

BOP stacks (Ref 2).

Unocal in Indonesia were the first to really extend the SBOP concept with their saturation drilling program which

started in the mid 1990’s. The initial program was with an 18-3/4” BOP suspended in the moonpool from the

SEDCO 602.

The 2nd phase utilized a 13-5/8” BOP used from the Sedco 601 and when additional riser uplift was required an air

can was installed. Using a 13-5/8” SBOP system the Sedco 601 could work in 6,700 ft water depth.

The 3rd phase was using the Ocean Baroness an enhanced Victory class rig with and 18-3/4” BOP suspended in the

moonpool using line hydraulic tensioners with a capacity of 3.6MM lbs.

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Following the Unocal experience Shell used the Sedco 601 to drill 3 wells using SBOP technology in 2001 and

drilled a further 2 wells using the Stena Clyde outfitted with a 13-5/8” BOP.

Total used the system with a SID to drill 1 well and a sidetrack in 2003.

In 2004 Shell expanded the regions where SBOPs have been utilized from the Far East to the Mediterranean and

offshore Brazil using the Stena Tay. It is notable that the Stena Tay is a DP MODU and extensive risk and well

assessments were undertaken by Shell to use the Stena Tay rig for this operation (Ref 3).

Following the success of the Stena Tay exploration drilling campaign Shell Brazil utilized the Arctic I rig to

undertake the development of the BC-10 field on Brazil using a SBOP. Again the Arctic I rig is rated for 3,000 ft

WD but with a pre-set mooring system and a SBOP worked in nearly 6,700 ft of water. A SID was deployed susbsea

during this campaign. (Ref 4).

In 2009 Murphy Oil installed a Floating Drilling Production Storage and Offloading (FDPSO) system in West

Africa.

The conclusion from this history is that the SBOP is a viable alternative methodology for drilling and development of subsea

wells in deepwater utilizing 3rd and 4th generation rigs which are both water depth and deck load limited. Furthermore, with

the safety culture of today a SBOP system with high pressured casing riser operated from a MODU can only be envisaged

with a subsea isolation device. The SID enables you to seal the well in the event of riser leakage/failure, provides a means to

shut-in and seal the well in the event of a drift off or drive off and provides a backup well control barrier in the event that the

riser leaks or fails.

The objective of this paper is to provide a description of the approach an operator new to this technology should adopt to

ensure that the associated design issues and risks are identified and properly assessed and effectively managed.

SBOP Environmental Considerations

Unlike SSBOP operations which are the norm and can operate in all metocean environments, the review of the history of

SBOP operations shows that they have primarily been used in benign environments which are historically defined by the

maximum design environment (Wind, Wave, Tide, and Current) which allows for rig offsets and heave to accommodate the

reduced riser tensioner stroke. Such environments exist primarily in South East Asia.

When operators move away from South East Asia and encounter more moderate environments such as the environmental

conditions in Brazil, West Africa and the Mediterranean there is a requirement for full riser tensioner stroke to accommodate

the expected increase in heave, tidal changes and vessel offsets. The return period environments must account for the

seasonal extremes provided the drilling program start and duration are known. Note the abnormal pressures and need for

many casing strings is likely to exclude the Gulf of Mexico.

SBOP System Design Considerations

The surface stack design will be determined by the well construction requirements. Historically the standard SBOP is a 13-

5/8” BOP stack, although as the history of SBOPs states BOP Stacks up to 18-3/4” have been utilized in the SBOP

configuration.

Generally the application of SBOP technology in deepwater prospects is where the predicted well designs are normally

pressured and the well targets are relatively shallow allowing a simplified casing program.

In drilling exploration programs the riser size is determined by the number of casing strings required to reach the well

objectives. When in development drilling the SBOP system riser size will be determined by the number of casing sizes, and

the required well diameter at the TD to facilitate an appropriate completion size. Also in development drilling there are

additional size considerations around the tubing hanger system.

One of the factors that have to be considered in the SBOP system is that as riser sizes increase so does the complexity of the

system. Larger risers such as a 16 inch High Pressure Riser requires greater wall thickness and this has an associated impact

on the tension capacity requirements of the system. For a 16 inch riser in 6,000 ft water it is not unusual to need

approximately 2-MM lbs top tension to meet API requirements.

To mitigate some of the top tension requirements it is possible to install buoyancy on the riser but this is only a limited

answer to the increased tension requirements and there is a trade off to be made with the associated increase in riser drag

loading due to increased diameter and increased riser stress.

The SBOP is generally located above the splash zone to minimize environmental loading on the BOP. All operations

described in the history of SBOPs are from semi-submersible rigs, both DP and moored, with the exception of the Azurite

FDPSO.To prevent contact with the sides of the rig under various vessel motions the moonpool must be able to accommodate

the SBOP including any frame to avoid contact between the BOP, tensioner wires and the hull. It is also prudent wherever

practical to minimize the height of the BOP.

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3 System Configuration

The following is a brief description of the traditional SBOP system components. Figure 2 presents an overview of the main

SBOP components.

Surface Stack Arrangements The SBOP stack design and size is very much determined by the well construction requirements and in most applications a

13-5/8” stack will be sufficient for exploration drilling of typical SBOP reservoirs. If appraisal drilling with well testing and

development drilling are a consideration then the riser size and BOP size may have to be increased. In the Shell BC-10

development a 16” dedicated high pressure riser was purpose built for the development program (Ref 4).

A typical base case SBOP design configuration for the 13-5/8” is a 3 ram preventer rated for 10,000psi working pressure with

a 5,000psi annular.

Tensioning Ring The tensioning ring is usually purpose built to suit the number of tensioning lines required to provide adequate top tension.

The tensioner ring can be located either underneath the annular preventer or incorporated into the telescopic joint body.

Again the location is a function of a number of factors which must be considered in the assessment process.

Telescopic Joint The rig’s telescopic joint stroke out will have a considerable impact on the rig operability with respect to vessel excursion.

This factor will be assessed in the mooring analysis of the rig. The top connection of the TJ must be able to connect to the

exiting diverter ball joint connection. The bottom connection needs to interface with the top of the SBOP annular preventer.

BOP Connector and Upper Riser Mandrel In all SBOP configurations the upper riser mandrel is flanged at the top to the upper stress joint.

The upper riser mandrel primarily serves as the connection between the SBOP and the riser. The upper stress joint provides

the transition from the SBOP to the main riser.

Stress Joint Stress joints are deployed on all SBOP configurations to mitigate the effect of fatigue in the riser at known fatigue hot spots.

Depending on the configuration these hot spots are generally located just below the SBOP and above the SID. The design of

the stress joint is critical and will vary, subject to fatigue life requirements, vessel motions, manufacturing limitations and

operational requirements. Again the assessment of this fatigue life is an important design consideration.

Riser Should a 13-5/8” SBOP be used then it is typical to use 13-3/8” grade P-110 68ppf casing with premium connections as the

high pressure riser. It is recommended practice that this casing is only used for 1 well as a HP riser. Again if appraisal or

development drilling is to be undertaken then the size of the riser is driven by well construction requirements such as the

number of casing strings required, size of the casing hangers/running tools well test equipment and well completion

requirements. Particular attention should be paid to the connectors and their fatigue design performance. Historical evidence

has shown that riser leakage/failure is most likely to be a connection failure due to fatigue or a small leak that escalates to

major failure.

Riser Buoyancy and VIV suppression.

A site specific riser analysis will determine the actual riser configuration but to reduce the top tension requirements it is

possible that more elaborate riser system designs are required for a particular operation. Such system could include

buoyancy modules on the riser and strakes or fairings to mitigate environmental conditions associated with VIV.

Subsea Isolation Device

The SID serves as an independent well control barrier in the event of a riser leak or failure. The SID provides the capability

to shut in the well in the event of an emergency such as the catastrophic failure of the riser. It is important to recognize that

the SID is not a control device; it is a basically an isolation device. It will have a control system and connectors to allow it to

connect to the riser and the wellhead. Various configurations of SID have been utilized from a 2 shear ram package to a

single shear ram and variable bore ram. The configuration is very much dependent upon the type of operation that is to be

conducted with the SBOP. The shear rams should be capable of shearing the drill pipe used by the rig for the drilling

program.

Control System Various SID control system configurations have been utilized. These have varied from a simple acoustic control system with

ROV back up to more complex MUX systems. Again the type of control system is very much dependent upon the type of

operations to be conducted and the risks associated with that operation.

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Subsea Wellhead.

The subsea wellhead serves multiple functions depending upon the drilling and or completion program. Firstly the subsea

wellhead serves as a high pressure housing and structural foundation mechanism for the whole system. The subsea wellhead

mandrel provides a connection point for the SID. The subsea wellhead also provides a landing point and sealing area for any

casing hangers that may be used in well construction.

A critical element of the design of the subsea wellhead and well is for the well below the mudline to have greater strength and

fatigue resilience than the system above the SID so that any failure point in the system is above the SID and not below it.

This is critical if the system were to fail prematurely.

4 Concept Selection Stage – Rig Selection and Early Well Planning

During the early stages of a project a number of key factors influence decision making such as project economics, rig

availability and early well construction plans. It is important at this stage to identify any number of obstacles or design

constraints which will influence the success of your riser and BOP system. Some recommended assessments include:

Risk Assessment / HAZID - At concept selection a high-level HAZID should be performed to identify potential

hazards and design risk for the different systems. The key consideration at concept selection is to keep hazard

identification general enough to broadly identify the high-impact risks to the system, allowing design and

implementation of physical barriers to mitigate catastrophic consequences. A generic HAZID checklist that

describes examples of typical system hazards can facilitate identification of risks. Performing a qualitative risk

assessment at this stage can allow evaluation of the concept, or may even be used to evaluate, compare and select a

particular concept based on hazard and risk tolerability.

Preliminary cost assessment

Evaluation of site soil conditions

Early well and casing program design

System pressure rating - Definition of Maximum Anticipated Surface Pressure and Temperature.

Definition of expected reservoir conditions (presence of H2S, levels of CO2)

Definition of maximum mud weight for various stages of drilling and completion.

Preliminary assessment of site metocean conditions with particular attention paid to site specific metocean events

like hurricanes / typhoons / cyclones, high surface currents (river delta, VIV), internal waves (solitons), topographic

Rossby waves (TRW).

Uptime assessment - Preliminary operability and Drift-Off/ Drive Off assessment to confirm if DP rig can operate in

the environment with sufficient time to ready the riser, and seal the well in an EDS scenario. If not then it may be

required to moor the rig.

Pros and Cons Assessment of the different systems

Risk Assessment/HAZID

The primary objective of a risk assessment is to evaluate the risk exposure of an asset and identify its critical subcomponents

in a structured manner so that potential failures and risks can be mitigated to as low as reasonable practical (ALARP) levels.

A risk assessment requires input from a variety of personnel, including key project stakeholders and subject matter experts

from design and operations.

The most catastrophic risk associated with drilling activities is a blow-out. The Macondo incident has “recalibrated” the

global understanding of the potential consequence from a blowout. Loss of well control that permits unrestrained flow from a

prolific reservoir to the environment has a catastrophic consequence for the health & safety (fatalities and injuries),

environment (spills into the ocean) and financial (cost associated with companies’ reputation, cleanup activities, etc). Before

Macondo, few people even suspected that the consequence of a blowout could be several tens of billions dollars. Historically

blowouts are considered low-probability/ high-consequence events; insufficient data are available in the industry to

accurately perform reliability analysis. Experience demonstrates that reliability parameters (likelihood of occurrence) can be

off by an order of magnitude or more.

History has shown that virtually all blowouts occur due to multiple low-probability events. For example, connections

sometimes have minor defects or damages, inspection fails to identify defects and testing techniques are unable to detect the

defects. Once system becomes operational under transient effects of temperature, pressure and load conditions, small leaks

may develop and escalate into large leaks. Systems (BOP, risers, valves, etc) must be designed with enough safety factors to

handle all environmental and operating loads; nevertheless, failures may still occur. It is necessary to recognize that most

failures occur well below the design load limits.

Under current “risk culture”, in order to mitigate low probability events, industry is designing more redundant systems; it is

highly recommended the use of dual independent well control barriers. Risk analyses will corroborate the implementation of

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multiple independent barriers in order to reduce the probability of failures. For instance, if a single barrier provides a

probability of only one chance in a thousand of failure then two independent barriers will provide one in a thousand times a

thousand chance of failure, i.e., only one chance in a million.

In order to perform the risk assessment effectively, this process must:

Prioritize the hazards in terms of likelihood and consequence to the system according to some clearly defined

standard (i.e. assess risk);

Ensure the system risks are tolerable and understood by the regulators, designers and most importantly, those that

will operate and manage the facility;

Quantitative and qualitative risk assessment techniques can be used in the development of the overall risk profile assessment

for the system. At the highest level, risk is assessed purely qualitatively and is best suited to allow identifying risk level of

different concept options where the stage of design definition is at its minimum. This allows an initial screening to eliminate

trivial potential hazards prior to a more detailed quantitative assessment, by focusing on all the processes that affects

reliability. As the project progresses through the various project stages, the focus of the risk assessment will change, as the

system becomes better defined.

Pros and Cons Discussion 1. The primary advantage of the use of a SID system is that it provides an additional independent well isolation barrier

for the wellbore in the event of a catastrophic failure.

2. The use of a SBOP for well control allows for direct accessibility for inspection and maintenance without the

significant downtime associated with subsea BOPs.

3. Using a traditional SSBOP presents a number of issues associated with well control. In deepwater the use of a

SSBOP is far from ideal for managing well control issues. There are issues around excessive pressure drop in long

choke lines, short time before a kick is above the BOP, and gas expansion in the riser which can result in a

catastrophic failure at the surface. With an SBOP system the issue of gas above the BOP stack is eliminated.

4. The potential for a hydrate to form below the SSBOP or in the choke and kill lines can seriously complicate well

control problems.

5. Hydrate formation in the SID will have its own specific challenges.

6. Traditional marine risers typically have bolted flange connections while high pressure SBOP risers employ premium

threaded and coupled connections. Each system presents separate challenges; pre-tension, bolt hardness, thread

design, make-up torque and must be designed to prevent leakage and fatigue failure.

7. Dropped BOPs or SIDS could cause long periods of downtime, with the associated knock on effects to project

timescales etc.

8. The variable deck load of the rig is enhanced due to the smaller riser system required for the SBOP system. One of

the main disadvantages of the SBOP system is the limitation on the number of casing strings that can be

accommodated without ending up with too small of final casing size. Only a few areas can use the casing program

30”or 36” conductor, 13 5/8” HPWH and 13 3/8” casing installed riserless. This doesn’t leave much room for

additional casing strings and still be able to run large tubing that is required for deepwater high rate completions.

The use of bi-centered bits to under ream the holes and even expandable liners are enablers, but these tools increase

the well cost.

9. The addition of a subsea wellhead system and SID causes a step-change in operational time for drilling a well. A

SBOP system with SID offers some advantages over SSBOP operations but the time saving differences are small.

10. Due consideration should be given to the probability of emergency disconnect. With an SBOP/SID system

emergency shearing of the drillpipe may render the well unrecoverable.

11. As industry goes into deeper water the associated drilling and completion costs can approach 40 to 50% of a

project’s costs when using conventional SSBOP and a 5th or 6th generation rig with high day rates. The use of a

SBOP/SID and a 2nd or 3rd generation rig has the potential to reduce these drilling costs and make what may be an

unviable project viable. The SBOP enables operators to access a wider selection of drilling units generally older 3rd

and 4th generation MODUs which come with an associated lower spread costs. The delta between a 3rd/4th

generation rig and a 5th/6th generation rig can be in the region of $100k to $150k per day. Although some of this

delta can be offset by the ‘off-line’ capability of the 5th/6th generation rigs.

5 Pre-Feed – Well Planning

This section deals with the risk assessment and technical analyses recommended for the well planning stage.

During Pre-FEED, risk assessment seeks for identification and selection of best project concepts and lessons learned; the

process may focus on identifying:

Design reviews of systems with similarity and key lessons learned and potential hazards from previous projects;

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Risk-based prioritization of planned analyses and design requirements; metrics established to assess relative risk and

integrity management mitigation standards for comparison of design options;

Barrier analysis for identified hazards and the proposed well design configuration; and

Preliminary reliability and availability requirement definitions and analysis.

During this phase, reliability data may be reviewed to establish typical preventative maintenance requirements and address

regulatory compliance issues. Risk-based recommendations may be made on the types of analysis to be performed during

FEED and detailed design and on particular sub-components that require reliability centered maintenance (RCM).

Development of barrier diagrams (such as bow-tie diagrams) provides a useful means for integrating risk assessment results

and integrity management measures.

At this stage the riser system design has progressed from selection to preliminary design analyses to establish the design

specifications. The environmental conditions are chosen to reflect the maximum operating conditions expected during the

design life. Design criteria, such as maximum and alternating stresses, are used in the selection of parameters, such as wall

thickness and material properties. Burst, collapse and preliminary strength assessment should be performed to validate the

wall thickness and material properties and for preliminary sizing of upper/lower tapered stress joints (SBOP only). The

analysis includes the performance of the drilling vessel and should also be used to assess the available vessel's riser-

tensioning requirements.

In all cases the selected space out of the riser system should be such that API RP 16Q (Ref. 5) tension requirements for

stability and disconnection are satisfied for expected mud weights. Furthermore, the Dynamic Tension Limit of 90% of

available tension should not be exceeded and top tension requirements may be reduced through the use of distributed

buoyancy rated for the design water depth. Selection of the correct riser wet weight is critical for emergency disconnect and

will be discussed later.

Among the functional constraints are the angles at both the lower flex/ball joint (SSBOP system only) and the upper flex

joint, the mean and alternating stresses, the resistance to column buckling and hydrostatic collapse, the percentage of the

dynamic tension limit (DTL) applied to the top of the riser and forces and moments transferred to the wellhead and casing.

For areas of high current an initial vortex induced vibration (VIV) analysis should be performed to determine if there is a

requirement for VIV suppression such as strakes/fairings, bearing in mind the nature and duration of the drilling/completion

activity.

For moored rigs a preliminary mooring analysis to determine suitable configuration, number and make up of lines, anchor

positioning and holding capacity is recommended at this stage. A mooring risk assessment in accordance with API RP 2SK

(Ref. 6) should be performed to determine suitable design conditions for the mooring system. The mooring system design

should be taut enough so that the mean and maximum offsets for various environmental conditions give a reasonable drilling

operating envelope for the rig. Thruster assistance may be used to reduce the mean offsets but this complicates the mooring

design and reinstates the potential risk of a drive-off event.

The option for shear rams on a SBOP stack should be a risk based consideration during the planning stage.

6 Detailed Design

The design of an SBOP drilling riser system more closely resembles a platform drilling riser; with a surface BOP stack, a

high pressure riser and tapered stress joints at top and bottom than it does a traditional marine drilling riser. The riser system

should be designed to the standards set out in API RP 16Q with additional considerations for operation of a high pressure

system.

If the riser system is intended for multiple well operations it should be designed for a pre-determined life, with appropriate

safety factors, and should have proven collapse, strength and fatigue resistance considering maximum expected mud weight,

maximum rated water depth and maximum expected overpressure. Furthermore, site specific operational limitations should

be determined for the respective rig and riser system.

Analysis of the drilling riser should consider all elements which might change the static and dynamic (short/long term)

response of the riser system; the tension distribution, the curvature profile, the radial and hoop stresses. A fully integrated

solution including the following is required:

Vessel dynamics (1st and 2nd order)

Dynamic tensioner performance

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Emergency disconnect and recoil performance

Auxiliary line effects and load sharing (if applicable)

Non-linearity’s such as soil deformation (P-y curves) and flex joints performance at higher angles

Conductor-casing deflection

Environmental loading from current, wind and wave

Fluctuating pressure loads

The riser system shall be designed for connected (drilling and non-drilling) and disconnected modes of operation. The

connected drilling mode is that combination of environmental and well conditions in which all normal drilling activities can

be safely conducted, including drilling ahead, tripping, circulating, etc. Special operations, such as running casing,

cementing, or formation testing, can dictate more restrictive operating limits. In connected non-drilling mode, the only

drilling operation that should be conducted is circulating. The drillpipe should not be rotated.

Each mode of connected operation, including, testing, normal operation, extreme operation and survival (well control) should

be analyzed for drilling and completion activities.

The SBOP riser system should be designed to accommodate the maximum anticipated surface pressure.

Operational analysis should account for accidental conditions such as:

Tensioner failure (loss of tension or tensioner lock-up).

Motion compensator failure (completion) (loss of tension or compensator lock-up)

Loss of vessel station-keeping, e.g. dynamic positioning failure or mooring line failure.

Wave Fatigue analysis should be performed to confirm the suitability of the riser system in terms of wall thickness, tapered

stress joint design, connector design etc. The tapered stress joints control the fatigue damage at critical hotspots at the top

and bottom of the riser and should be adequately sized for strength and fatigue resistance. In addition careful attention

should be paid to the splash zone area and fatigue analysis may dictate a heavier wall joint to be used here to offset the

additional loading from waves and currents.

In SBOP drilling it is common to use high strength smaller diameter casing (e.g. 13-5/8” P110) as the high pressure riser.

The recommendation generally is to only use this casing in a dynamic application once and to deploy it downhole or replace

it completely for the next well. The casing will accumulate fatigue damage on each well and tracking the accumulate damage

and location of the damage is important.

There are two fundamental approaches to a fatigue analysis. The first approach is based on fatigue tests and S-N (stress range

versus number of cycles) curves and can take the form of either deterministic or stochastic (spectral method) calculations.

The second approach is based on fracture mechanics principles. For a drilling riser, both approaches require knowledge of

the magnitude and probability of occurrence of the expected sea states during either the riser's life or recommended

inspection interval. These expected sea states form the “fatigue weather spectrum” used in the fatigue analysis. The fatigue

life of the riser is defined as the total life to riser failure, i.e., the life until the riser fails (“critical failure”). The S-N approach

is a good method to estimate the initial fatigue life of a riser for assumed environmental conditions. The fracture-mechanics

method, when coupled with an inspection program, is appropriate for estimating the remaining fatigue life of a riser after use.

Both long term and short term (extreme event) Vortex Induced Vibration analysis should be performed to calculate the

possible damage from VIV. This is particularly important for high current areas and areas of submerged currents. Note if the

riser is covered with VIV suppression then the wave fatigue analysis should consider this also.

Weak-point analysis can be performed to predict the most probable point of failure in the riser/wellhead system. This analysis

can be used to select structural casing and wellhead equipment in order to ensure wellbore containment in this extreme event.

This is particularly important for moored rigs and helps to define a datum for the mooring design. Ideally the weakpoint in

the system shall be outside the damaged mooring offset of the rig for respective environmental conditions.

As the concept of SBOP is novel to some members of the drilling community there are a number of issues that should be

addressed to identify hazards associated with the technique of SBOP operations compared to SSBOPs. These techniques

include a formal well construction Hazard Analysis which can then be used to develop a Drill the Well on Paper (DWOP)

exercise with both engineers and operations personnel. In addition depending upon the operations to be undertaken a BOP

HAZOP process can be used to address issues of well control and isolation of the well using both a SSBOP and SID systems.

Although a SBOP provides some improvements in well control compared to a conventional SSBOP the general deepwater

drilling community will not be as familiar with such well control techniques. Therefore again these issues will need to be

addressed during the DWOP exercise, and specialist training given to rig personnel in well control.

Following more detailed design analysis there should be a better definition of the uncertainties associated with design

parameters, new technologies and commercial issues, enabling a more accurate evaluation of risk. HAZID/HAZOP analysis

and failure diagrams such as fault trees and event trees may be used in the risk assessment process at this stage. The

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assessments should be able to take HSE and production regulations into consideration.

However, despite having a larger quantity of defined system information, caution should be taken when assessing risk, as

parameters can change throughout the design process. Design and operations teams should be educated on the critical failure

modes and critical parameters associated with these should be identified in the risk assessment, to be captured later as

anomaly limits for the system. It should be highlighted that if these parameters change in the design stage the risk impact

may need to be re-assessed.

Once the design is fixed, a detailed HAZOP and qualitative and quantitative risk assessments, taking into account mitigations

or safeguards considered during design can be performed. In addition, the process provides greater confidence in the final

design criteria, allowing definition of:

Minimum specification for condition monitoring and inspection equipment;

Maintenance Plan

Metrics to assess design conservatism; and

Qualification assessment.

Throughout the design process risk registers should be used to track actions resulting from the risk assessment; these actions

may include validation or re-assessment of operating strategies, verification of design parameters, or design and

implementation of additional barriers.

During detailed design subsea components and subassemblies (e.g. valves) are identified. Once design criteria are well

established interfaces are recognized for the specification of equipment for procurement. This allows more lead time for

identification and scheduling of critical tasks and for review and approval of FAT procedures by client personnel.

When all of the hazard and risk analysis is completed should the MODU possess a Safety (HSE) Case then the document

should be updated with the changes and submitted to interested stakeholders for review and comment. These stakeholders

could include partners as well as regulatory bodies.

7 Manufacture

Proper quality assurance and control (QA/QC) practices should provide assurance during the manufacturing process. Major

concerns are attributed to manufacturing problems, such as poor welding or lack of ECA criteria, etc. In review of the

QA/QC processes, it should be ensured that there is accurate means to measure parameters (e.g. ovality of bore pipe), and

detect defects (e.g. ultrasonic inspection).

Correct implementation of procedures is critical, including management of change procedures, and detailed recording and

tracking of non-conformances during the manufacturing process. Unrecorded changes to manufacturing or repair procedures

can lead to catastrophic failures. In addition it is important that a system integration test (SIT) is conducted prior to

installation to minimize uncertainties during the commissioning stage.

8 Operation Planning

Riser analysis should also be used in preparation for operating. In this case the objective is to establish operational constraints

of the system. Further, the analysis indicates the environmental conditions during which drilling should be stopped and when

it is prudent to set downhole plugs and disconnect the riser.

Normal Operation – Connected Drilling

Connected Drilling Operability analysis is performed to determine the maximum vessel excursion from well centre and

maximum allowable environment (combination of current velocity and significant wave height/period) that drilling

operations can be performed. The rig is offset in both the upstream and downstream direction monitoring ball/flex joint

angle, riser/TSJ stresses, moonpool clashing, tensioner / telescopic joint stroke, connector bending moments, and casing-

conductor bending moments and stresses.

Generally under normal drilling conditions riser angles in SBOP systems are characterized by angles through the riser with a

mean of <2 degrees limit and vessel excursion less than 2% of water depth.

In the majority of the areas where SBOPs have been deployed this condition is likely to exist in up to at least 99% non

exceedence storm and current profile.

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Survival – Connected Non-Drilling For the Connected Non-Drilling mode of operation with conventional SSBOP systems the ball/flex joint allowable limit may

be increased to 90% of available, as per API RP 16Q however operational constraints such as SBOP/riser clashing with

moonpool will likely supersede this limit. In SBOP riser systems the stresses in the upper and lower stress joints (LSJ) will

increase with offset and environment and should be closely monitored. Riser analysis will predict the potential for excessive

riser angles or vessel excursions. There may be more severe limitations in the event of a well control or well testing situation

which may require the riser operation to be curtailed earlier. One of the attractive features of SBOP drilling has been to utilize older generation moored rigs in deeper water. The

mooring system is designed to minimize the mean vessel excursion to maximize the operating envelope for the rig. A taut

leg mooring configuration has distinct advantages in this area. Key to making the taut leg system work is minimizing line

weight, (polyester rope systems have been successfully used in the past), and maximizing anchor holding capacity (e.g.

vertically loaded anchors). The mooring system should be designed in accordance with API RP 2SK or DnV-OS-E301

(Ref. 7) and should consider a damaged mooring line condition.

Survival – Disconnected If conditions escalate to the point where the system will not maintain pressure integrity the well will be secured with

downhole plugs and the riser disconnected and either suspended from the vessel or fully retrieved. For a moored rig this

condition represents the maximum mooring system design condition under which the riser and BOP should be examined in

respect to interference in the moonpool for hull/moonpool contact. An environmental condition on the order of a 10 year

return storm event should be considered for this condition.

Storm hang-off analysis is performed to demonstrate that during hang-off, all the limits on stress, SBOP/Riser-moonpool and

SID-wellhead clearances and rotations are satisfied for the riser and the other equipment used in implementing hang-off. The

analysis determines the operating limits for the riser, the optimum configuration (i.e. required number of slick joints at the

bottom) and the feasibility of hard or soft hang-off.

The feasibility of running/retrieving the riser is also assessed. Critical stages of deployment are analyzed to determine a safe

deployment environmental envelope for the riser. Special attention shall be given to deployment of SID and SBOP in the

moonpool, through the splash zone and landing of the SID subsea

Emergency Disconnection

Unplanned conditions like the following may require emergency disconnection of the riser at the BOP/SID:

Loss of well control

Multiple mooring line failures (with no thruster assistance)

Drift-Off (loss of vessel power when operating in DP mode)

Drive-Off (loss of vessel control when operating DP or Thruster Assisted Mooring mode)

Drift-off/drive-off analysis of a drilling riser system identifies disconnect limits for dynamically-positioned (DP) vessels.

Specifically, this analysis is used to determine yellow-alert and red-alert offsets that alert the crew that the vessel is drifting

or driving off. An Emergency Disconnection Sequence (EDS) typically requires 30 s to 70 s to complete depending on the

system sequencing and what is across the SSBOP/SID. A significant change in offset can occur in this short amount of time

leaving insufficient time to replace the mud in the riser with seawater and reduce top tension to prepare for disconnect.

Disconnection of the riser causes the riser to recoil and accelerate upwards. Failure to control recoil effectively can result in

the structural limits of several components in the load path being exceeded (e.g. telescopic Joint inner barrel, upper ball/flex

joint(s), diverter, rotary table, etc.). A complete Riser-Recoil analysis simulates the system's behavior under various

conditions and can provide guidance on TJ/tensioner stoke-out, recoil control system settings, criteria and operating limits in

terms of tension, mud weight, and vessel motion.

It is necessary that a realistic riser-recoil simulation model the tensioner system in detail, accounting for the kinematics of all

moving parts (including the air and oil), forces, pressures and friction. Similar detail is also required in the mud column in

order to simulate accurately the load that the mud column imparts on the riser. A detailed recoil analysis is prudent for DP

operations which use a SBOP as the weight of the LMRP is not present to help retard the riser and so optimization of the

space-out is paramount.

9 Operations

Many factors can detrimentally affect the integrity of a barrier. These escalation factors include such things as out-of-

specification materials, corrosion, improper installation procedures and poor management processes. A leak in any one of the

hundreds of connected components is a barrier failure. Escalation control or mitigation factors such as testing, monitoring

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and active corrosion control can reduce the effects. These activities do not add barriers to the system; they only improve the

reliability of the physical well control barriers.

As mentioned risers are subjected to potential failure modes which include Environmentally Assisted Cracking (EAC), VIV,

Fatigue, overload, incorrect design. Associated with these potential failure modes are inadequate riser maintenance and

inspection programs which have been identified as root causes of riser failures.

During the operation of the SBOP system compared to a SSBOP system there should be a number of activities which can be

used to familiarize the rig crews with the particular operations of the SBOP. Prior to the start of the operation a

familiarization exercise should be undertaken with the rig crews to gain familiarity with the new equipment. As pointed out

earlier the equipment has a number of advantages over SSBOP operations of which the most notable include weight and size

of the equipment compared to the SSBOP. The handling and operating procedures for the SBOP equipment should be

converted to Job Safety Analysis worksheets prior to the operation is essential to ensure a smooth and safe operation. These

JSA shall be reviewed by the crews prior to the start of operations and updated with learning’s through After Action Reviews

(AARs).

To ensure the integrity of the BOP system and the riser specialist contractors should be considered to provide assurance

services. These will include thorough BOP/SBOP inspection prior to the start of any operations and replacement of any worn

or damaged components. A specialist Casing Thread Inspection Company can be employed to provide assurance the casing

threads are not damaged when running a casing riser. These may seem like overkill but the potential for loss of integrity or

functionality during the operation can be catastrophic in terms of risk.

Should the operation opt for a dedicated SBOP drilling riser, a wear management plan similar to that already proven to

effectively manage riser wear on TLP drilling riser should be implemented to ensure riser integrity is not compromised e.g.

no surface testing of motors or MWD/LWD tools while running the BHA, use of appropriate drillpipe hard-banding and

careful monitoring of the ditch magnet.

10 Conclusions

Based on current industry practices, the proposed systems studied in this paper could potentially be designed with sufficient

robustness and safety margins to provide reliable integrity and operability. The selection of a particular system as fit is based

on balancing a number of factors, including site-specific characteristics, risk and cost. Today risk analysis tools formalize

thoughtful analyses that capture input from both experienced personnel and specialists from many disciplines. As such, it is

recommended that selection should be driven by an assessment of total risk to the system to clearly identify the most critical

hazards.

11 References

1 SPE 87111 – 2005 Surface BOP: Testing and Completing Deepwater Wells Drilled with a Surface BOP Rig. D.L

Mason SPE, W. Tharp Shell International E&P and C.L. Willie SPE Power Well Services

2 SPE/IADC 103754 – 2006 Surface BOP- Recent Experience and Future Opportunities, John Kozicz, Transocean

3 IADC/SPE 87113 – 2004 Drilling in Brazil in 2887m Water Depth using a Surface BOP Stack and a DP Vessel. G

Bander, E Magne, T Newman, T Taklo (Shell International Exploration and Production) and C Mitchell (Shell

Brazil Exploration and Production).

4 IADC/SPE 112788 – 2008 Surface BOP System for Subsea Development Offshore Brazil in 1900M of Water

B.A.Tarr SPE, T Taklo SPE, A Hudson, L.A. Olijnik, and H Shu Shell and R. Greff Transocean.

5 API RP 16Q, Recommended Practice for Design, Selection, Operation and Maintenance of Marine Drilling Riser

systems, 1st edition, November, 1993.

6 API RP 2SK, Recommended Practice for Design and Analysis of Stationkeeping Systems for Floating Structures, 3rd

edition, October, 2005.

7 DnV-OS-E301, Offshore Standard Position Mooring, October 2004.

12 OTC 22714

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Figure 1: General arrangement of Surface BOP and Subsea BOP with SID systems

Figure 2: SBOP Drilling / Completion System